Wellbore Packer And Method

ABSTRACT

A wellbore packer for setting against a wellbore wall in a wellbore, the wellbore packer including: a mandrel including a upper end and an lower end; and an outer housing encircling the mandrel and including a first compression ring, a second compression ring, an annular packing element encircling the mandrel and positioned between the first compression ring and the second compression ring, the sealing element being expandable to form an annular seal about the packer by compression between the first compression ring and the second compression ring; and an anchoring mechanism including a slip that is expandable outwardly into a set position and a slip actuation assembly to drive expansion of the slip.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims priority to U.S. Provisional Application No. 61/768,742 filed on Feb. 25, 2013, which is hereby incorporated by reference in its entirety.

FIELD

The invention relates to a wellbore packer and method.

BACKGROUND

Wellbore packers are employed for fluid control and isolation. For example, packers are employed to control fluid flows and to isolate and direct injected fluids.

SUMMARY

In accordance with a broad aspect of the present invention, there is provided a wellbore packer for setting against a wellbore wall in a wellbore, the wellbore packer comprising: a mandrel including a upper end and an lower end; and an outer housing encircling the mandrel and including a first compression ring, a second compression ring, an annular packing element encircling the mandrel and positioned between the first compression ring and the second compression ring, the sealing element being expandable to form an annular seal about the packer by compression between the first compression ring and the second compression ring; and an anchoring mechanism including a slip that is expandable outwardly into a set position and a slip actuation assembly to drive expansion of the slip.

Also provided is a method for setting a packer against a wellbore wall in a wellbore, the method comprising: running into the wellbore with a wellbore packer connected to a tubing string, the wellbore packer including: a mandrel including a upper end and an lower end; and an outer housing encircling the mandrel and including a first compression ring, a second compression ring, an annular packing element encircling the mandrel and positioned between the first compression ring and the second compression ring, the sealing element being expandable to form an annular seal about the packer by compression between the first compression ring and the second compression ring; and an anchoring mechanism including a slip that is expandable outwardly into a set position and a slip actuation assembly to drive expansion of the slip; applying force to the packer to push the outer housing down over the mandrel, while the second compression ring is held stationary to compress the packing element and to cause the packing element to expand outwardly against the wellbore wall; and continuing to apply force to compress the anchoring mechanism to drive the slip to expand outwardly into engagement with the wellbore wall.

It is to be understood that other aspects of the present invention will become readily apparent to those skilled in the art from the following detailed description, wherein various embodiments of the invention are shown and described by way of illustration. As will be realized, the invention is capable for other and different embodiments and its several details are capable of modification in various other respects, all without departing from the spirit and scope of the present invention. Accordingly the drawings and detailed description are to be regarded as illustrative in nature and not as restrictive.

BRIEF DESCRIPTION OF THE DRAWINGS

A further, detailed, description of the invention, briefly described above, will follow by reference to the following drawings of specific embodiments of the invention. These drawings depict only typical embodiments of the invention and are therefore not to be considered limiting of its scope. In the drawings:

FIG. 1 is a sectional view along the long axis of a packer in an inactive, run in condition.

FIG. 2 is a sectional view along a long axis of the packer of FIG. 1 operating in a wellbore. The packer is in a set position.

FIG. 3 is a sectional view along a long axis of the packer of FIG. 1 in a wellbore string and in a later stage of operation. Here the packer is shown after shear release.

DETAILED DESCRIPTION OF VARIOUS EMBODIMENTS

The description that follows and the embodiments described therein are provided by way of illustration of an example, or examples, of particular embodiments of the principles of various aspects of the present invention. These examples are provided for the purposes of explanation, and not of limitation, of those principles and of the invention in its various aspects. The drawings are not necessarily to scale and in some instances proportions may have been exaggerated in order more clearly to depict certain features. Throughout the drawings, from time to time, the same number is used to reference similar, but not necessarily identical, parts.

A wellbore packer and method have been invented.

With reference to FIGS. 1 to 3, one embodiment of a wellbore packer 10 is shown. These figures show the packer 10 sometimes positioned in a wellbore, shown by wall 12. FIG. 1 shows the packer in an inactive condition. This is the packer's condition during run in to a wellbore. FIGS. 2 and 3 show the packer operating in the wellbore.

Although this type of packer is often employed in a cased wellbore, it is to be noted that the wellbore may be cased or open hole, such that wall 12 may be a casing inner surface or exposed formation.

Packer 10 is formed operate in the wellbore and for example has an outer diameter to fit within wall 12. Wall 12 forms a constraining surface about the packer and the packer can be deployed and set to create an annular seal between the wall and the packer.

Although not shown in detail, packer 10 may be carried, via its upper end, on a manipulation string 14, through which the packer 10 can be axially moved and manipulated from surface. String 14 may have a flexible or axially rigid, solid or tubular form. String 14, for example, may include line, rods, coil tubing, interconnected tubulars, etc.

Packer 10 may be recognized by those in the field as an injection-type packer and includes an outer housing 16 and an inner mandrel 18.

Mandrel 18 provides a body about which outer housing 16 is mounted. The mandrel can be closed, if the packer is to act as a plug in the wellbore, or may have a bore 18 a therethrough from its upper end 18 b to its lower end 18 c, as shown, through which fluids can be injected below the packer. Mandrel 18 at its upper end is formed to be supportable on string 14. In this embodiment, upper end 18 b includes a thread form 20 into which a string may be secured by threaded engagement. It may be useful to employ a latch seal assembly 23 that can become engaged into thread form 20 by stabbing straight in but can only be removed by unthreading from thread 20. In one embodiment shown in FIG. 3, a string 14 a carries a latch seal assembly 23 that includes a mandrel latch including radially outwardly biased collet fingers 25 with an externally threaded surface 27. The threaded surface 27 spans the collet fingers and forms a continuous threaded pin end. The collet fingers can collapse inwardly to allow connection with the packer by a straight insertion into end 18 b, but the collet fingers being biased outwardly drive threaded surface 27 into engagement with the thread 20 such that the latch seal assembly can only be removed from end 18 b by reverse threading the collet fingers 25 from thread 20.

Mandrel 18 further includes a bore portion 21 into which an injection string can be inserted and sealed. Bore portion 21, sometimes referred to as a seal bore or polished bore, may include a surface to facilitate sealing therein of an injection string, such as a latch seal assembly 23. To facilitate sealing with the seals 23 a of an injection string, the surface may be smoother than other mandrel surfaces. For example, bore portion 21 may be polished. Bore portion 21 may extend fully through the mandrel or may have an axial length less than the length of the mandrel. For example, in the illustrated embodiment, bore portion 21 extends down to a shoulder 24. The shoulder is upwardly facing with the inner diameter being greater above than below and, thus, presents a surface against which the injection string may be set to limit its insertion.

Mandrel 18 may further include mounting site for a bore plug. In this illustrated embodiment, the mounting site is a profile 26 for accepting the bore plug, if one is desired. A bore plug controls fluid communication through the bore from end 18 b to end 18 c and may be a valve or a solid wall and may be permanent or removable (i.e. burstable, expellable, openable, etc.). The illustrated profile is an annular indentation, for example, for an Otis X or XN blanking plug, but of course other forms are possible.

Mandrel 18 carries structures on its outer surface 18 d for operation with outer housing 16. For example, the mandrel may include sites, such as glands or indentations 28, 29, for accepting connection with the outer housing, a shoulder 30 for acting against outer housing 16 and a ratchet structure 33 for locking the position of the outer housing relative to the mandrel.

Mandel 18 may be made of interconnected parts, as is usual for wellbore tools, or the mandrel may be one piece, as shown. A one piece part, as shown, which is devoid of connections such as threaded connections, ports, seals, etc. may be useful. The absence of threaded connections in the bore along the length of the mandrel avoids potential leak paths and the need for seals to be installed, and allows the length of the tool to be reduced over mandrel constructions employing a plurality of parts threaded together.

The function of the mandrel and the parts thereof will be better understood in the description hereinbelow regarding the packer operation.

Outer housing 16 has an overall cylindrical form that encircles the mandrel. Outer housing 16 has an inner diameter through which the mandrel extends such that the outer housing and the mandrel are assembled substantially coaxially about long axis x.

Outer housing 16 includes the packer's one or more packing elements 36. Packing elements 36, when set, create an annular seal in the wellbore about the packer extending between the mandrel outer surface 18 d and the wellbore wall.

Outer housing 16 further includes a lower packing element compression ring 37, also called a gauge ring, on a lower housing segment 38 and an upper packing element compression ring 40 on the upper, opposite side of the packing elements from ring 36. Rings 37, 40 transfer compression force to the packing elements therebetween and direct the packing elements to be extruded radially outwardly.

Outer housing 16 further includes an anchoring mechanism, for example, including slips 22 and a slip actuation assembly. Slips 22 are spaced apart about a circumference of the mandrel and formed to be settable to expand out and engage the wellbore wall. The slips may have teeth formed on their outer facing surfaces 22 a to bite into the wellbore wall, when set into contact with the wall. The slip actuation assembly includes parts formed to drive the slips out into a set position. The slip actuating assembly may also include components to retain the slips in a retracted position until they are driven out to set. In this illustrated embodiment, the slips each include a backside 22 b that is frusto-conically formed at each end. Thus, the slips are ramped on their backside surface where the slip thickness tapers from a mid region toward the ends. In this embodiment, the slip actuation assembly includes an upper cone 42 and a lower cone 44 that are each axially moveable and drivable behind the slips to act against the backside frusto-conical surfaces and drive the slips radially out to the expanded position. The slip actuation assembly also includes an axially rigid slip cage 46 releasably secured at one end, as by shear pins 48, to upper cone 42 and releasably secured at the opposite end, as by shear pins 50, to lower cone 44. Slips 22 are aligned with openings 46 a in the slip cage and can pass therethrough, as they expand and retract.

A locking body 52 is also provided as a part of the outer housing. Locking body 52 includes an inwardly facing ratchet surface 54 formed to act with ratchet surface 33 on mandrel 18. The ratchet teeth on the ratchet mechanism, including ratchet surfaces 33, 54 allow movement of locking body 52 in a downward direction but not in the reverse. In other words, locking body 52 can move toward lower end 18 c, but not in the reverse direction (i.e. toward upper end 18 b).

Locking body 52 also includes an upper end 52 a that forms a shoulder protruding out from mandrel outer surface 18 d.

Housing 16 also includes an inwardly facing shoulder 58 to act with shoulder 30 on mandrel 18.

Locking body 52 and upper cone 42 are connected for movement together at connection 60.

In the illustrated embodiment, packing elements 36 are positioned closer to the lower end 18 c of mandrel than the other components. In particular, as illustrated, the anchoring assembly and ratchet mechanism are positioned between packing elements 36 and the upper end of the packer, which is upper end 18 b of the mandrel. Since fluids are generally injected below packer, this positioning isolates the injected fluids from the operational mechanisms, thereby reducing potential corrosion problems.

Thus, as illustrated, lower cone 44 is connected to upper ring 40 through a connection 62. This connection, connection 60 and pins 48, 50 connect the components of the outer housing above elements 36, such that they all move in unison until pins 48, 50 shear.

Outer housing 16 is normally retained in place on mandrel by a releasable lock, such as shear pins 56 engaged between locking body 52 and recess 28 and shear pins 64 engaged between lower housing segment 38 and recess 29. The releasable lock on the upper end has a lower holding force than the releasable lock on the lower end, such that the upper connection through shear pins 56 can be overcome before that holding the lower end. This allows a relative movement of upper end, for example locking body 52, relative to the lower end, for example, lower housing segment 38 and locking body can be made moveable over mandrel 18 while the lower housing segment remains attached to the mandrel. The strongest releasable locks, in this embodiment, pins 64, cannot be overcome by setting the packer. Thus, pins 64 hold the mandrel in place in the outer housing while the packer is in use.

In use, packer 10 is attached to string 14 and run into the well. The packer is set by expanding the packing elements 36 and slips 22 such that the elements 36 form an annular seal between mandrel 18 and wall 12 and slips bite into the wellbore wall and hold the packer firmly in place against tool manipulations and pressure differentials.

The packer is set by holding the mandrel while pushing down on locking body 52. The packer may be set in various ways, such as by electrical drive, hydraulics, mechanical, etc.

In one embodiment, for example, string 14 may include a line such as wireline for example, electric wireline. In such an embodiment, the packer may be attached to a setting tool with a wireline adapter kit. The packer can then be run into the well on wireline and at a position of interest, the packer may be set by a force generated by the wireline setting tool. At a predetermined force, the wireline adapter kit may disengage from the packer. Thereafter, the setting tool, adapter kit and wireline are retrieved from the hole, leaving the packer set in the wellbore.

In another embodiment, string 14 may include tubulars that can apply a push force on the tool. For example, if the operation requires deployment in a deviated or horizontal well, then packer placement may require a push force to be applied to the packer during deployment. In such an embodiment, the packer can be deployed on a string formed of tubing and may be pushed into the well. A hydraulic setting tool may be attached to the tubing string and an adapter kit may be employed to attach the packer to the hydraulic setting tool. Pressure applied down the tubing is converted to a force to push the locking body down relative to the mandrel to set the packer. The tubing pressure may also be employed to disengage the adapter kit from the packer, after it is set.

The force applying body of the adapter kit can be set against upper end 52 a shoulder of the locking body. While the mandrel is held steady, the force to set the packer is applied to locking body 52. Once pins 56 shear, the force continues through locking body 52 to upper cone 42, slip cage 46, lower cone 44 and then into packing elements. Since lower end segment 38 is held in place by pins 64, the movement of the upper components squeezes ring 40 against elements 36 and elements 36 against ring 37 and causes the packing elements to expand radially outwardly.

After packing elements 36 have fully expanded, the force is no longer taken up by the packing elements. Thereafter, shear screws 50 located between lower cone 44 and the slip cage shear allowing the slips to shift onto the lower cone. Once slips 22 contact lower cone 44, they are pushed radially outwardly from the mandrel toward wellbore wall 12. After contacting wall 12, shear pins 48 between the upper cone and the slip cage break, allowing the upper cone 42 to also be pushed under the backsides 22 b of the slips.

Once the cones 42, 44 are fully wedged under slips 22, with the slips biting into wall 12, the packer is fully set (FIG. 2). The ratchet surfaces 33, 54 of the ratchet mechanism trap the setting force against mandrel 18. As noted above, the teeth of the ratchet mechanism are selected to allow movement of the locking body toward lower end 18 c, but not in the reverse.

This lower component to upper component setting sequence (i.e. (i) packing elements expand, (ii) lower cone (between packing elements and slips) wedges under the slips, and (iii) upper cone wedges under the slips), ensures that the packer anchors inside the wellbore properly and forms a high pressure seal between mandrel 18 and wall 12. If the upper cone wedged prior to any of the lower components, the force could not be transferred through and the packer setting would be incomplete. The setting sequence may be achieved by selection of the shear pin failure rating. The shear pins 50 and 48 have a holding force greater than the force required to expand the packing elements and shear pins 48 have a holding force greater than that of the shear pins 50 for the lower cone.

After the packer is set, it can operate to hold pressure in the wellbore. If the mandrel is closed, the packer may operate immediately acting as a plug, such as a bridge plug in the well. If the packer is intended to assist with injection operations, an injection string can be run in to connect to the mandrel and inject through the packer.

In an injection operation, for example, at surface a latch seal assembly is attached to a tubing string 14 a and run into the well. If the packer mandrel is closed, for example, it has a plug in its mandrel for example, at profile 26, the packer may act as a bridge plug in the well and snubbing of the string may not be necessary. At depth, latch seal assembly 23 is stabbed into the packer. Collet fingers 25 drive threaded surface 27 into engagement with the thread 20 and seals 23 a on the latch seal assembly engage bore portion 21 on the packer. An annular pressure test may ensure that seals 23 a are sealing are there are no leaks in the tubing connections. The annular pressure test ensures the packer is set properly after the integrity of tubing string 14 a, latch seal assembly 23 and packer 10 have been determined. The mandrel may then be opened, as by overcoming (i.e. pumping out, bursting, opening, etc.) any plug in the bore of the mandrel. The plug can be overcome by using applied pressure down string 14 a. Once the bore of the mandrel has been opened, communication is established with the wellbore below the packer. Fluid injection can then be commenced.

During the fluid injection process, if tubing string 14 a needs to be removed, a plug can be set inside the mandrel, for example in profile 26. Tubing string 14 a and latch seal assembly 23 can then be separated safely from the packer and retrieved to surface. This may be accomplished by rotation of the latch seal assembly, for example right hand rotation to unthread the parts, and then pulling up.

If/when the operator decides to remove the packer, it can be released by pulling up on mandrel 18, as shown in FIG. 3. The mandrel can be pulled up by pulling the string 14 a into tension while latch seal assembly 23 is engaged in thread form 20. Some other packers require the use of an injection string and a separate releasing string, but the same string may be used for both operations in this packer. In particular, the latch seal with its collet fingers 25 and external threaded surfaces 27 cannot be pulled straight out of engagement with thread form 20, but instead must be unthreaded by employing more than a quarter turn rotation. The engagement of mandrel 18 by latch seal assembly 23 is, therefore, quite reliable and can only be overcome by significant rotation of the latch seal assembly relative to the packer. This requirement for reverse (i.e. right hand) threading makes an inadvertent release unlikely.

Since slips 22 and packing elements 36 are set, pulling up on the mandrel moves the mandrel up through outer housing: shearing pins 64, which removes the compressive force setting slips 22 and elements 36. The housing 16 can stretch and elements 36 and slips can relax and retract. Other packer mechanisms may be employed to facilitate release of the compressive force. In particular, when the packer is to be released, mandrel 18 is pulled up to shear pins 64. Shoulder 30 on mandrel 18 also moves up and pulls against locking body 52, which pulls upwardly on upper cone 42. This causes upper cone 42 to shift from beneath slips 22 and, as well, to pull up slip cage. For example, a shoulder 43 on upper cone 42 may catch on a shoulder 45 on slip cage, so that both cone 42 and slip cage move up. When pulled up, the lower end of opening 46 a on the slip cage butts against the lower ends of slips and pulls slips 22 off lower cone 44. The slips then can retract. The release of compressive force through shearing of pins 64 also allows elements 36 to relax and retract. The upward movement of the housing components above elements 36 facilitates and speeds the retraction of the packing elements.

The previous description of the disclosed embodiments is provided to enable any person skilled in the art to make or use the present invention. Various modifications to those embodiments will be readily apparent to those skilled in the art, and the generic principles defined herein may be applied to other embodiments without departing from the spirit or scope of the invention. Thus, the present invention is not intended to be limited to the embodiments shown herein, but is to be accorded the full scope consistent with the claims, wherein reference to an element in the singular, such as by use of the article “a” or “an” is not intended to mean “one and only one” unless specifically so stated, but rather “one or more”. All structural and functional equivalents to the elements of the various embodiments described throughout the disclosure that are known or later come to be known to those of ordinary skill in the art are intended to be encompassed by the elements of the claims. Moreover, nothing disclosed herein is intended to be dedicated to the public regardless of whether such disclosure is explicitly recited in the claims. No claim element is to be construed under the provisions of 35 USC 112, sixth paragraph, unless the element is expressly recited using the phrase “means for” or “step for”. 

1. A wellbore packer for setting against a wellbore wall in a wellbore, the wellbore packer comprising: a mandrel including a upper end and an lower end; and an outer housing encircling the mandrel and including a first compression ring, a second compression ring, an annular packing element encircling the mandrel and positioned between the first compression ring and the second compression ring, the sealing element being expandable to form an annular seal about the packer by compression between the first compression ring and the second compression ring; and an anchoring mechanism including a slip that is expandable outwardly into a set position and a slip actuation assembly to drive expansion of the slip.
 2. The wellbore packer of claim 1 wherein the mandrel has a one piece construction from the upper end to the lower end.
 3. The wellbore packer of claim 1 wherein the mandrel includes a bore extending from the upper end to the lower end and the mandrel is devoid of threaded connections between parts open into the bore.
 4. The wellbore packer of claim 3 wherein the mandrel includes a tubing connection site at the upper end and the bore includes a seal bore portion extending from the tubing connection site toward the lower end.
 5. The wellbore packer of claim 4 wherein the tubing connection site is a threaded box.
 6. The wellbore packer of claim 3 wherein the bore includes a plug profile for accepting installation of a plug in the bore.
 7. The wellbore packer of claim 1 wherein the anchoring mechanism is positioned between the upper end and the packing elements.
 8. The wellbore packer of claim 1 wherein the slip actuation assembly is selected to operate to set the slips only after the packing element has expanded.
 9. The wellbore packer of claim 1 wherein the slip actuation assembly is selected to wedge a lower cone under the slip before an upper cone is wedged under the slip.
 10. The wellbore packer of claim 1 further comprising a ratchet mechanism to lock compressive force into the anchoring mechanism and the packing element.
 11. A method for setting a packer against a wellbore wall in a wellbore, the method comprising: running into the wellbore with a wellbore packer connected to a tubing string, the wellbore packer including: a mandrel including a upper end and an lower end; and an outer housing encircling the mandrel and including a first compression ring, a second compression ring, an annular packing element encircling the mandrel and positioned between the first compression ring and the second compression ring, the sealing element being expandable to form an annular seal about the packer by compression between the first compression ring and the second compression ring; and an anchoring mechanism including a slip that is expandable outwardly into a set position and a slip actuation assembly to drive expansion of the slip; applying force to the packer to push the outer housing down over the mandrel, while the second compression ring is held stationary to compress the packing element and to cause the packing element to expand outwardly against the wellbore wall; and continuing to apply force to compress the anchoring mechanism to drive the slip to expand outwardly into engagement with the wellbore wall.
 12. The method of claim 11 wherein the packing element expands before the slip expands outwardly.
 13. The method of claim 11 wherein the anchoring mechanism includes a lower cone between the slip and the packing element and an upper cone and compression of the anchoring mechanism drives the lower cone behind the slip and thereafter the upper cone is driven behind the slip.
 14. The method of claim 11 further comprising injecting fluids through a bore in the mandrel to a position below the packing element and the packing element isolating the fluids from the anchoring mechanism.
 15. The method of claim 11 further comprising inserting an injection string into a bore in the mandrel, the injection string engaging the mandrel and being sealed against the bore.
 16. The method of claim 15 further comprising injecting fluids from the injection string through the mandrel to a position below the packing element.
 17. The method of claim 15 further comprising pulling the injection string into tension to unset the packer.
 18. The method of claim 17 further comprising retrieving the packer to surface on the injection string. 